Acid gas removal from various gas streams and especially removal of CO2 from natural gas streams has become increasingly important as the sweet gas fields are being depleted. High CO2 gas fields remained unexplored, mostly due to their lower heating values and high capital and operating costs. However, with the recent increase of natural gas prices, gas producers started to explore these high CO2 fields. High CO2 gas fields exist in many regions of the world, including Alaska, Gulf of Mexico, South American and South China, particularly coal bed methane fields in North America. The CO2 content of these fields can reach 40 mol % and higher, which would require unconventional CO2 removal technologies to meet today's sales gas pipeline specifications, emissions requirements, and energy efficiency. Additionally, CO2 removed from these fields must be re-compressed to high pressure for Enhanced Oil Recovery and CO2 sequestration to reduce overall greenhouse gas emissions. Moreover, a viable CO2 removal process must also be economically viable and environmentally compliant.
There are numerous processes for acid gas removal known in the art, and all or almost all of those may be categorized into one of three categories. In the first category, a chemical solvent is employed that reacts with the acid gas to form a (typically non-covalent) complex with the acid gas. In processes involving a chemical reaction between the acid gas and the solvent, the feed gases are typically scrubbed with an alkaline salt solution of a weak inorganic acid as, for example, described in U.S. Pat. No. 3,563,695, or with alkaline solutions of organic acids or bases as, for example, described in U.S. Pat. No. 2,177,068. Such chemical reaction processes generally require heat regeneration and cooling of the chemical solvents, and often involve recirculation of large amounts of chemical solvent, thus making the use of chemical solvents uneconomical for the high CO2 gas fields.
In the second category, one or more membranes are used to separate CO2 from a gas stream based on differential permeability of the gas components. A typical membrane system includes a pre-treatment skid and a series of membrane modules. Membrane systems are often highly adaptable to treat high CO2 content gases, and are relatively compact making them particularly suitable for offshore application. However, they are susceptible to deterioration from heavy hydrocarbons and tend to require frequent and costly replacement. In addition, CO2 removal to a relatively low CO2 content (2 mol % or less) to meet sales gas specification typically requires multiple stages of membrane separators and re-compression between stages. More problematic is that the CO2 permeate contains a significant amount of methane since methane is also a fast gas. With high CO2 feed gases, methane losses from the membrane systems could be significant, making these applications also often uneconomical.
In the third category, a physical solvent is employed for removal of acid gas from a feed gas, wherein the acid gas is absorbed in an appreciable amount with the solvent. The physical absorption of the acid gas predominantly depends upon use of solvents having selective solubility for the particular acid gas (e.g., CO2 or H2S) and is further dependent upon pressure and temperature of the solvent. Since physical solvent unit operation follows the principal of Henry's law, CO2 loading of the solvent increases with the CO2 partial pressure in the feed gas, which would make physical solvents ideal for use in high pressure high CO2 gas fields. Solvent regeneration can be accomplished, to some extent, by flash regeneration, minimizing or eliminating the need of heating. However, the physical solvent processes require large cooling duty in removing the CO2 absorption heat, and may also need significant heating for solvent regeneration. Without improved methods and configurations, the physical processes may also be cost prohibitive.
Exemplary attempts have been undertaken for CO2 removal. For example, U.S. Pat. No. 7,273,513 teaches feeding gas stream and liquid stream into a first contactor where they are contacted co-currently and subjected to turbulent mixing conditions, and passing the multi-phase flow from the first contactor to a second contactor. While such process provides improved contacting devices suitable for amine solvents (chemical processes), it fails to address the methods and configurations for heat removal, solvent regeneration, hydrocarbon losses and CO2 production of physical solvent processes. Improved CO2 removal processes with physical solvents are described in WO2004/052511, U.S. Pat. No. 7,424,808, and U.S. Pat. No. 7,192,468, where an ultra-lean solvent is produced by recycle/clean gas stripping or use of a vacuum stripper, and where the feed gas is cooled by refrigeration obtained from treated gas and flashing of solvent. While such processes advantageously improve energy efficiency, various disadvantages nevertheless remain. For example, the absorber requires a relatively large number of contacting stages, and the overall process is relatively complex. In yet other known processes, as described in WO2010/039785, the lean solvent is regenerated using waste heat generated in the plant, and feed gas cooling is achieved by the treated gas. While such process typically simplifies plant configurations, cooling requirements are not met and a separate cooling circuit for the lean solvent is required.
Thus, although various configurations and methods are known to remove acid gases from a feed gas, all or almost all of them suffer from one or more disadvantages. Among other things, the CO2 levels in the treated gases are often high, and use of physical solvent requires significant solvent circulation and refrigeration cooling. Therefore, there is still a need to provide improved methods and configurations for efficient acid gas removal.